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An evaluation system of hydrocarbon-bearing availability of fault traps was established based on the comprehensive analysis of fault segment growth history, fine reservoir anatomy and geochemistry tracing, with the Qikou sag in the Bohai Bay Basin as target area. The displacement/separation transform and displacement gradient method were used to prove the interpretation reliability of fault traps. The method of maximum throw subtraction was used to recover the history of fault growth and determine the availability of the forming period of fault traps. Based on the quantitative relationship between shale gouge ratio and cross-fault pressure difference of known reservoirs in southern Qikou sag, the critical shale gouge ratio of fault lateral sealing was calculated at 20%, and the quantitative evaluation chart based on the relationship of "fault throw-sand-formation ratio and hydrocarbon column height" was constructed. Based on the results of reservoir fine anatomy and quantitative fluorescence tracing test shale smear factor method is suitable for evaluating the vertical sealing of faults in the caprock of the middle submember of first member of Paleogene Shahejie Formation, and the shale smear factor critical value is 3.5. The juxtaposition thickness method is suitable for evaluating vertical sealing of faults in the caprock of the second member of Paleogene Dongying Formation, and the critical juxtaposition thickness of fault is 70-80 m. By combining four factors, the availability of fault trap interpretation, the availability of the forming period of fault trap, the availability of fault lateral sealing and the availability of fault vertical sealing, the comprehensive evaluation chart on hydrocarbon-bearing availability of fault traps in Qikou sag has been established, which provides a reasonable basis for risk assessment of fault traps.
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In view of strong heterogeneity and complex formation and evolution of organic pores, field emission scanning electron microscopy (FESEM), Raman spectrum and fluid injection + CT/SEM imaging technology were used to study the macerals, organic pores and connectivity of organic pores in the lower Paleozoic organic-rich shale samples from Southern China. Combined with the mechanism of hydrocarbon generation and expulsion and pore forming mechanism of organic matter-based activated carbon, the relationships between organic pore development and the organic matter type, hydrocarbon generation process, diagenesis and pore pressure were explored to reveal the controlling factors of the formation, preservation and connectivity of organic pores in shale. (1) The generation of organic pores goes on through the whole hydrocarbon generation process, and is controlled by the type, maturity and decomposition of organic matter; the different hydrocarbon generation components and differential hydrocarbon-generation evolution of kerogen and solid asphalt lead to different pore development characteristics; organic pores mainly develop in solid bitumen and hydrogen-rich kerogen. (2) The preservation of organic pores is controlled by maturity and diagenesis, including the steric hindrance effect of in-situ hydrocarbon retention, rigid mineral framework formed by recrystallization, the coupling mechanism of pore-fluid pressure and shale brittleness- ductility transition. (3) The Ro of 4.0% is the maturity threshold of organic pore extinction, the shale layers with Ro larger than 3.5% have high risk for shale gas exploration, these shale layers have low gas contents, as they were in an open state before uplift, and had high hydrocarbon expulsion efficiency and strong aromatization, thus having the "congenital deficiency" of high maturity and pore densification. (4) The pores in the same organic matter particle have good connectivity; and the effective connectivity between different organic matter pores and inorganic pores and fractures depends on the abundance and distribution of organic matter, and development degree of pores and fractures in the shale; the accumulation, preservation and laminar distribution of different types of organic matter in high abundance is the prerequisite for the development and connection of organic pores, grain margin fractures and bedding fractures in reservoir.
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Biogenic quartz in the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation (Wufeng- Longmaxi) shale layers in the Sichuan Basin and its periphery is qualitatively analyzed and quantitatively characterized by organic petrologic, mineralogic, and geochemical methods to find out the coupling effect between organic matter and quartz. (1) There are two types of biogenic quartz in the shale layers: Type I quartz is submicron quartz appearing in clusters around the organic matter. Type II quartz is in nano-scale grain size and floats in spherical shape on organic matter, with grains in point-to-point or surface-to-surface contact; this type of quartz is mainly biologic origin and slightly affected by hydrothermal activity in local parts. (2) The reservoirs in the Wufeng-Longmaxi formations is consistent in distribution with biogenic silica content in them, and mainly concentrated at the bottom of the Wufeng-Longmaxi formations, and is thinner in the Changning and Weiyuan regions, while thicker in the Fuling region. (3) The biogenic quartz in the Wufeng-Longmaxi shale worked through the entire evolution process of hydrocarbon generation. The presence of biogenic quartz can enhance the development of organic matter pores and microcracks, and can effectively preserve the organic matter pores and residual intergranular pores, forming "biological silicon intergranular pores, organic pores and micro-fractures". This would benefit later hydraulic fracturing and result in high production/stable production of well. The coupling effect between biogenic quartz development and organic matter evolution and hydrocarbon generation is a critical factor for high-quality shale reservoir development.
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To improve the efficiency and accuracy of carbonate reservoir research, a unified reservoir knowledge base linking geological knowledge management with reservoir research is proposed. The reservoir knowledge base serves high-quality analysis, evaluation, description and geological modeling of reservoirs. The knowledge framework is divided into three categories: technical service standard, technical research method and professional knowledge and cases related to geological objects. In order to build a knowledge base, first of all, it is necessary to form a knowledge classification system and knowledge description standards; secondly, to sort out theoretical understandings and various technical methods for different geologic objects and work out a technical service standard package according to the technical standard; thirdly, to collect typical outcrop and reservoir cases, constantly expand the content of the knowledge base through systematic extraction, sorting and saving, and construct professional knowledge about geological objects. Through the use of encyclopedia based collaborative editing architecture, knowledge construction and sharing can be realized. Geological objects and related attribute parameters can be automatically extracted by using natural language processing (NLP) technology, and outcrop data can be collected by using modern fine measurement technology, to enhance the efficiency of knowledge acquisition, extraction and sorting. In this paper, the geological modeling of fracture-cavity reservoir in the Tarim Basin is taken as an example to illustrate the construction of knowledge base of carbonate reservoir and its application in geological modeling of fracture-cavity carbonate reservoir.
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Aiming at the complicated problem of the genesis of high-quality hybrid sedimentary rocks, the pore-throat systems, controlling factors and fluid mobility of hybrid sedimentary rocks in the Permian Lucaogou Formation in Jimusar Sag were examined. The results show that the hybrid sedimentary rocks contain 5 types of pore-throat system, intergranular (Type A), mixed intergranular-dissolved-intercrystalline (Type B), dissolved (Type C), mixed dissolved-intercrystalline (Type D) and intercrystalline (Type E) ones. The pore-throat systems are controlled by 3 major factors, the component content and arrangement (CCA) of hybrid sedimentary rocks, sedimentary environment and diagenesis. CCA controls the matrix support mode of hybrid sedimentary rocks, and therefore controls the types and changes of pore-throat system. The sedimentary environment mainly controls the macroscopic distribution of pore-throat system, i.e., hybrid sedimentary rocks deposited in the near source and high-energy environment are characterized by high content of coarse-grained component, granular/interbedded-support mode, and development of Type A and Type B pore-throat systems. Hybrid sedimentary rocks deposited in the medium-energy environment far from source are characterized by dolomitic/mud support mode and Type C and Type D pore-throat systems. Hybrid sedimentary rocks deposited in low-energy environment far from source have mainly Type E and Type D pore-throat systems. Diagenetic processes such as compaction and calcite cementation make the proportions of Type A and Type C pore-throat systems decrease further. In the hybrid sedimentary process of sandy-mud, pore-throat system types show a change of “A→B→C→D”, in that of dolomite-sand, pore-throat system types show a change of “A→C→D→E” or “B→D→E”, and in that of dolomite-mud, pore-throat system types show a change of “D→E”, which are affected in details by the contents of coarse-grain component, feldspar and dolomite. The reservoir with Type A pore-throats has the best physical properties and fluid mobility, and the reservoirs with Type D and Type E pore-throats have the poorest. The movable fluid distribution is related to the matrix support mode, and the larger pores in hybrid sedimentary rocks of dolomite/mud support mode have no obvious advantage in fluid mobility. The findings of this study provide a geological basis for evaluating and building reasonable interpretation model of hybrid sedimentary rocks sweet spot.
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Based on field outcrop data, the effects of cyclic change of astronomical orbit and volcanic activity on organic carbon accumulation during the Late Ordovician - Early Silurian in the Upper Yangtze area were studied using cyclostratigraphic and geochemical methods. δ 13C and chemical index of alteration (CIA) were used to filter the astronomical orbit parameters recorded in sediments. It is found that the climate change driven by orbital cycle controls the fluctuations of sea level at different scales, obliquity forcing climate changes drive thermohaline circulation (THC) of the ocean, and THC-induced bottom currents transport nutrient-laden water from high latitude regions to the surface water of low-latitude area. Hence, THC is the main dynamic mechanism of organic-carbon supply. The marine productivity indexes of Ba/Al and Ni/Al indicate that volcanic activities had limited effect on marine productivity but had great influences on organic carbon preservation efficiency in late Hirnantian (E4). Paleo-ocean redox environmental indicators Th/U, V/Cr and V/(V+Ni) show that there is a significant correlation between volcanism and oxygen content in Paleo-ocean, so it is inferred that volcanisms controlled the organic carbon preservation efficiency by regulating oxygen content in Paleo-ocean, and the difference in volcanism intensity in different areas is an important factor for the differential preservation efficiency of organic carbon. The organic carbon input driven by orbital cycle and the preservation efficiency affected by volcanisms worked together to control the enrichment of organic carbon in the Middle-Upper Yangtze region.
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The characteristics and genesis of the calcite veins in Carboniferous basalt in the east slope of Mahu Sag, Junggar Basin are investigated based on observation of cores and thin sections; analyses of X-ray fluorescence, in situ major, trace and rare earth elements (REE), carbon, oxygen and strontium isotopes, fluid inclusions, as well as basin modeling. There are three periods of calcite fillings. The Period I calcite is characterized by low Mn content, flat REE pattern, strong negative cerium (Ce) anomaly, weak to moderate negative Eu anomaly, and light carbon isotopic composition, indicating the formation of the calcite was affected by meteoric water. The Period II calcite shows higher Mn and light REE contents, weak positive Ce anomaly and slight positive europium (Eu) anomaly, and a little heavier carbon isotopic composition and slightly lower strontium isotope ratio than the Period I calcite, suggesting that deep diagenetic fluids affected the formation of the Period II calcite to some extent. The Period III calcite is rich in iron and manganese and has REE pattern similar to that of the Period II calcite, but the cerium and europium enomalies vary significantly. The Period I and II calcites were formed in shallow diagenetic environment at approximately 250-260 Ma, corresponding to Late Hercynian orogeny at Late Permian. The Period III calcite was probably formed in the Indo-China movement during Late Triassic. It is believed that the precipitation of calcite in basalt fractures near unconformity was related to leaching and dissolution of carbonates in the overlying Lower Permian Fengcheng Formation by meteoric water, which destructed the Carboniferous weathering crust reservoirs in early stage. Relatively high quality reservoirs could be developed in positions with weak filling and strong late dissolution, such as structural high parts with Fengcheng Formation missing, distant strata from Fengcheng Formation vertically, buried hills inside lake basin, etc.
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Based on detailed investigation of the modern sedimentation of the distributive fluvial system of Shule River and the data of unmanned aerial vehicle (UAV) aerial photography and satellite remote sensing, the sedimentary characteristics and differences of distributive fluvial system in arid areas are analyzed. By comparing the changes in slope, river morphology and sedimentary characteristics in different sections from the apex to the toe, the distributive fluvial system of Shule River can be divided into three facies belts: “proximal”, “middle” and “distal”. The proximal belt has the largest slope and strongest hydrodynamic condition, mainly appears as large-scale braided river deposits; the fluvial bars in this belt are mainly composed of gravels, the gravels have good roundness and certain directionality, and are medium-large boulders, with low sand content; the main microfacies in this belt are braided channel and flood plain. The middle belt with slope smaller than the proximal belt, is mainly composed of braided bifurcating river deposits. Due to branching and infiltration, this belt has weaker hydrodynamic conditions, so some of the distributive rivers dry up, appearing as ephemeral rivers. This belt has small lenticular sandbodies, fine to medium gravels, higher sand content, and mainly braided channel, flood plain and aeolian dune microfacies. The distal belt has the smallest slope and flat terrain, where the river begins to transform from braided river to meandering river, the sediment is mainly sand. Due to the influence of slope, this belt has weaker erosion toward source and stronger lateral erosion, and point bars developing around the edge of the active lobes. In this belt, the river is completely meandering, and the main microfacies are braided channel, meandering channel, flood plain, aeolian dune, lake and swamp.
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The meandering channel deposit of the upper member of Neogene Guantao Formation in Shengli Chengdao extra-shallow sea oilfield is characterized by rapid change in sedimentary facies. In addition, affected by surface tides and sea water reverberation, the double sensor seismic data processed by conventional methods has low signal-to-noise ratio and low resolution, and thus cannot meet the needs of seismic description and oil-bearing fluid identification of thin reservoirs less than 10 meters thick in this area. The two-step high resolution frequency bandwidth expanding processing technology was used to improve the signal-to-noise ratio and resolution of the seismic data, as a result, the dominant frequency of the seismic data was enhanced from 30 Hz to 50 Hz, and the sand body thickness resolution was enhanced from 10 m to 6 m. On the basis of fine layer control by seismic data, three types of seismic facies models, floodplain, natural levee and point bar, were defined, and the intelligent horizon-facies controlled recognition technology was worked out, which had a prediction error of reservoir thickness of less than 1.5 m. Clearly, the description accuracy of meandering channel sand bodies has been improved. The probability semi-quantitative oiliness identification method of fluid by prestack multi-parameters has been worked out by integrating Poisson's ratio, fluid factor, product of Lame parameter and density, and other prestack elastic parameters, and the method has a coincidence rate of fluid identification of more than 90%, providing solid technical support for the exploration and development of thin reservoirs in Shengli Chengdao extra-shallow sea oilfield, which is expected to provide reference for the exploration and development of similar oilfields in China.
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Based on core, thin section, X-ray diffraction, rock pyrolysis, CT scanning, nuclear magnetic resonance and oil testing data, the macro and micro components, sedimentary structure characteristics, of Paleogene Kong 2 Member in Cangdong sag of Huanghua depression and evaluation standard and method of shale oil reservoir were studied to sort out the best shale sections for shale oil horizontal wells. According to the dominant rock type, rhythmic structure and logging curve characteristics, four types of shale lithofacies were identified, namely, thin-layered dolomitic shale, lamellar mixed shale, lamellar felsic shale, and bedded dolomitic shale, and the Kong 21 sub-member was divided into four quasi-sequences, PS1 to PS4. The PS1 shale has a porosity higher than 6%, clay content of less than 20%, and S1 of less than 4 mg/g; the PS2 shale has well-developed laminar structure, larger pore and throat size, better connectivity of pores and throats, high contents of TOC and movable hydrocarbon, S1 of over 4mg/g, clay content of less than 20%, and porosity of more than 4%; PS3 shale has S1 value higher than 6 mg/g and clay content of 20% - 30%, and porosity of less than 4%; and PS4 shale has lower TOC content and low oil content. Shale oil reservoir classification criterion based on five parameters, free hydrocarbon content S1, shale rhythmic structure, clay content, TOC and porosity, was established. The evaluation method of shale oil sweet spot by using the weighted five parameters, and the evaluation index EI were proposed. Through comprehensive analysis, it is concluded that PS2 is best in quality and thus the dual geological and engineering sweet spot of shale oil, PS3 and PS1 come next, the former is more geologic sweet spot, the latter more engineering sweet spot, and PS4 is the poorest. Several vertical and horizontal wells drilled in the PS2 and PS3 sweet spots obtained high oil production. Among them, Well 1701H has produced stably for 623 days, with cumulative production of over 10000 tons, showing bright exploration prospects of Kong 2 Member shale oil.
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The generation method of three-dimensional fractal discrete fracture network (FDFN) based on multiplicative cascade process was developed. The complex multi-scale fracture system in shale after fracturing was characterized by coupling the artificial fracture model and the natural fracture model. Based on an assisted history matching (AHM) using multiple-proxy-based Markov chain Monte Carlo algorithm (MCMC), an embedded discrete fracture modeling (EDFM) incorporated with reservoir simulator was used to predict productivity of shale gas well. When using the natural fracture generation method, the distribution of natural fracture network can be controlled by fractal parameters, and the natural fracture network generated coupling with artificial fractures can characterize the complex system of different- scale fractures in shale after fracturing. The EDFM, with fewer grids and less computation time consumption, can characterize the attributes of natural fractures and artificial fractures flexibly, and simulate the details of mass transfer between matrix cells and fractures while reducing computation significantly. The combination of AMH and EDFM can lower the uncertainty of reservoir and fracture parameters, and realize effective inversion of key reservoir and fracture parameters and the productivity forecast of shale gas wells. Application demonstrates the results from the proposed productivity prediction model integrating FDFN, EDFM and AHM have high credibility.
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"Generalized mobility" is used to realize the unification of tube flow and seepage in form and the unification of commonly used linear and nonlinear flow laws in form, which makes it possible to use the same form of motion equations to construct unified governing equations for reservoirs of different scales in different regions. Firstly, by defining the generalized mobility under different flow conditions, the basic equation governing fluid flow in reservoir coupling generalized tube flow and seepage is established. Secondly, two typical well test analysis models for coupling tube flow and seepage flow are given, namely, pipe-shaped composite reservoir model and partially open cylindrical reservoir model. The log-log pressure draw-down type-curve of composite pipe-shaped reservoir model can show characteristics of two sets of linear flow. The log-log pressure drawdown plot of partially opened cylindrical reservoir model can show the characteristics of spherical flow and linear flow, as well as spherical flow and radial flow. The pressure build-up derivative curves of the two models basically coincide with their respective pressure drawdown derivative curves in the early stage, pulling down features in the late stage, and the shorter the production time is, the earlier the pulling down feature appears. Finally, the practicability and reliability of the models presented in this paper are verified by three application examples.
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Waterflooding experiments were conducted in micro-models (microscopic scale) and on plunger cores from low permeability, extra-low permeability and ultra-low permeability reservoirs in the Ordos Basin under different displacement pressures using the NMR techniques to find out pore-scale oil occurrence state, oil production characteristics and residual oil distribution during the process of waterflooding and analyze the effect of pore structure and displacement pressure on waterflooding efficiency. Under bound water condition, crude oil mainly occurs in medium and large pores in the low-permeability sample, while small pores and medium pores are the main distribution space of crude oil in extra-low permeability and ultra-low permeability samples. During the waterflooding, crude oil in the medium and large pores of the three types of samples are preferentially produced. With the decrease of permeability of the samples, the waterflooding front sequentially shows uniform displacement, network displacement and finger displacement, and correspondingly the oil recovery factors decrease successively. After waterflooding, the residual oil in low-permeability samples is mainly distributed in medium pores, and appears in membranous and angular dispersed phase; but that in the extra-low and ultra-low permeability samples is mainly distributed in small pores, and appears in continuous phase formed by a bypass flow and dispersed phase. The low-permeability samples have higher and stable oil displacement efficiency, while the oil displacement efficiency of the extra-low permeability and ultra-low permeability samples is lower, but increases to a certain extent with the increase of displacement pressure.
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CO2 huff and puff experiments of different injection parameters, production parameters and soaking time were carried out on large-scale cubic and long columnar outcrop samples to analyze dynamic characteristics and influencing factors of CO2 huff and puff and the contribution of sweeping mode to recovery. The experimental results show that the development process of CO2 huff and puff can be divided into four stages, namely, CO2 backflow, production of gas with some oil, high-speed oil production, and oil production rate decline stages. The production of gas with some oil stage is dominated by free gas displacement, and the high-speed oil production stage is dominated by dissolved gas displacement. CO2 injection volume and development speed are the major factors affecting the oil recovery. The larger the injected CO2 volume and the lower the development speed, the higher the oil recovery will be. The reasonable CO2 injection volume and development speed should be worked out according to oilfield demand and economic evaluation. There is a reasonable soaking time in CO2 huff and puff. Longer soaking time than the optimum time makes little contribution to oil recovery. In field applications, the stability of bottom hole pressure is important to judge whether the soaking time is sufficient during the huff period. The oil recovery of CO2 huff and puff mainly comes from the contribution of flow sweep and diffusion sweep, and diffusion sweep contributes more to the oil recovery when the soaking time is sufficient.
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The numerical modeling of oil displacement by nanofluid based on three-dimensional micromodel of cores with different permeability was carried out by the volume of fluid (VOF) method with experimentally measured values of interfacial tension, contact angle and viscosity. Water-based suspensions of SiO2 nanoparticles with a concentration of 0-1% and different particle sizes were considered to study the effect of concentration and size of nanoparticles, displacement fluid flow rate, oil viscosity and core permeability on the efficiency of oil displacement by nanofluid. The oil recovery factor (ORF) increases with the increase of mass fraction of nanoparticles. An increase in nanoparticles’ concentration to 0.5% allows an increase in ORF by about 19% compared to water flooding. The ORF increases with the decrease of nanoparticle size, and declines with the increase of displacing rate. It has been shown that the use of nanosuspensions for enhanced oil recovery is most effective for low-permeable reservoirs with highly viscous oil in injection modes with capillary number close to the immobilization threshold, and the magnitude of oil recovery enhancement decreases with the increase of displacement speed. The higher the oil viscosity, the lower the reservoir rock permeability, the higher the ORF improved by nanofluids will be.
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Permeability sensitivity to stress experiments were conducted on standard core samples taken from Wen 23 Gas Storage at multi-cycle injection and production conditions of the gas storage to study the change pattern of stress sensitivity of permeability. A method for calculating permeability under overburden pressure in the multi-cycle injection and production process was proposed, and the effect of stress sensitivity of reservoir permeability on gas well injectivity and productivity in UGS was analyzed. Retention rate of permeability decreased sharply first and then slowly with the increase of the UGS cycles. The stress sensitivity index of permeability decreased with the increase of cycle number of net stress variations in the increase process of net stress. The stress sensitivity index of permeability hardly changed with the increase of cycle number of net stress variations in the decrease process of net stress. With the increase of cycle number of net stress variation, the stress sensitivity index of permeability in the increase process of net stress approached that in the decrease process of net stress. The lower the reservoir permeability, the greater the irreversible permeability loss rate, the stronger the cyclic stress sensitivity, and the higher the stress sensitivity index of the reservoir, the stronger the reservoir stress sensitivity. The gas zones with permeability lower than 0.3×10-3 μm 2 are not suitable as gas storage regions. Stress sensitivity of reservoir permeability has strong impact on gas well injectivity and productivity and mainly in the first few cycles.
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Azimuth gamma logging while drilling (LWD) is one of the important technologies of geosteering but the information of real-time data transmission is limited and the interpretation is difficult. This study proposes a method of applying artificial intelligence in the LWD data interpretation to enhance the accuracy and efficiency of real-time data processing. By examining formation response characteristics of azimuth gamma ray (GR) curve, the preliminary formation change position is detected based on wavelet transform modulus maxima (WTMM) method, then the dynamic threshold is determined, and a set of contour points describing the formation boundary is obtained. The classification recognition model based on the long short-term memory (LSTM) is designed to judge the true or false of stratum information described by the contour point set to enhance the accuracy of formation identification. Finally, relative dip angle is calculated by nonlinear least square method. Interpretation of azimuth gamma data and application of real-time data processing while drilling show that the method proposed can effectively and accurately determine the formation changes, improve the accuracy of formation dip interpretation, and meet the needs of real-time LWD geosteering.
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Current univariate approach to predict the probability of well construction time has limited accuracy due to the fact that it ignores key factors affecting the time. In this study, we propose a multivariate probabilistic approach to predict the risks of well construction time. It takes advantage of an extended multi-dimensional Bernacchia-Pigolotti kernel density estimation technique and combines probability distributions by means of Monte-Carlo simulations to establish a depth-dependent probabilistic model. This method is applied to predict the durations of drilling phases of 192 wells, most of which are located in the Australia- Asia region. Despite the challenge of gappy records, our model shows an excellent statistical agreement with the observed data. Our results suggested that the total time is longer than the trouble-free time by at least 4 days, and at most 12 days within the 10%-90% confidence interval. This model allows us to derive the likelihoods of duration for each phase at a certain depth and to generate inputs for training data-driven models, facilitating evaluation and prediction of the risks of an entire drilling operation.
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Some unusual events happened in petroleum industry in 2020, such as the negative WTI oil price, price soaring of melt-blown nonwoven fabric, Exxon Mobil Corp.(NYSE:XOM) removed from Dow Jones Industrial Average, and the oil demand peak theory proposed by BP Energy Outlook 2020 Edition. These events have made profound impact on petroleum exploration. Prospecting is at the forefront of petroleum industry chain, and prospectors have great influence on petroleum industry. The responsibility of petroleum prospectors is to find oil, which calls for the correct way of thinking as well as scientific and technical means, both of which are indispensable. When it comes to the cognition of petroleum exploration, we should draw lessons from predecessors’ philosophy of finding oil from a development perspective. It is necessary to define the relationship between subject activity and objective structure, as there is an inherent tension between the two and a dialectical relationship that complements each other. It is also essential to illustrate the logic of initiative and decisiveness, as between the two is the dual logic of active logic that changes the world and deterministic logic based on science and technology. The strategic breakthrough in the Gulong shale oil exploration in Daqing is a typical example. Our knowledge and practice of oil exploration has overthrown the Hubbert Curve. The new curve may have more than one peak, which means hopes are always there for finding oil. Climbing to the top of a mountain must start from the foot. A journey of a thousand miles must begin with a single step. Looking forward to the future, prospectors have the wisdom, ability, and methods to find more, cleaner, and more affordable oil to drive the progress of human civilization. This is the duty of petroleum prospectors.
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By reviewing the challenges in the development of oilfields in China under low oil prices, this study analyzes the root causes of cost rising, put forwards the low cost oilfield development strategy and specific paths to realize the strategy, and predicts the development potential and prospect of oilfields in China. In addition to the low grade of the reservoir and high development maturation, the fundamental reasons of development full cost rising of oilfields in China are as follows: (1) Facing the problem of resources turning poorer in quality, we have built production capacity at a pace too fast before making enough technical and experimental preparation; (2) technical engineering service model leads to high service cost; (3) team of oil development expertise and matched engineering system cannot satisfy the technical requirements of stabilizing oil production, controlling water cut and fine development. To realize development at low cost, the core is to increase economic recoverable reserves. The concrete paths include: (1) to explore the “Daqing oilfield development culture”, improve the ability of leaders in charge of development, and inspire potential of staff; (2) to improve the ability of reservoir dynamics control, and implement precise development by following scientific principles; (3) to speed up integration of water flooding and enhanced oil recovery (EOR) and technological upgrading in order to enhance oil recovery; (4) to innovate key techniques in gas flooding and accelerate the industrial popularization of gas flooding; (5) to break the related transaction barriers and create new management models; and (6) to collaboratively optimize strategic layout and cultivate key oil bases. Although oilfield development in China faces huge challenges in cost, the low-cost development strategy will succeed as long as strategic development of mature and new oil fields is well planned. The cores to lower cost are to control decline rate and enhance oil recovery in mature oil fields, and increase single well productivity through technical innovation and improve engineering service efficiency through management innovation in new oil fields.
